The production of hydrocarbons from a reservoir often causes production of non-hydrocarbon gases. Such gases include contaminants such as hydrogen sulphide (H2S) and carbon dioxide (CO2). When H2S and CO2 are produced as part of a hydrocarbon gas stream (such as methane or ethane), the raw gas stream is sometimes referred to as “sour gas.” The H2S and CO2 are often referred to together as “acid gases.”
Acid gases may also be associated with synthesis or refinery gas streams. Acid gases may also be generated by the combustion of carbon based materials such as coal, natural gas or other carbon based fuels. In any instance, raw gas streams may contain other “acidic” impurities. These include mercaptans and other trace sulphur compounds. Such impurities should be removed prior to industrial or residential use.
While H2S, mercaptans and trace sulphur compounds have long been captured through separation processes, CO2 has oftentimes simply been vented to the atmosphere. However, the practice of venting CO2 is coming into conflict with national or regional emission requirements which can limit CO2 emissions. Hence, processes for removing CO2 are of greater interest to industries that operate gas processing facilities, particularly within the oil and gas production industry.
There are a number of processes for removing acid gas from a raw natural gas stream or flue gas streams. A common method involves treating the hydrocarbon fluid stream with a solvent. Solvents may include chemical solvents such as amines. Examples of amines used in sour gas treatment include monoethanol amine (MEA), diethanol amine (DEA), and methyl diethanol amine (MDEA). Amine-based solvents rely on a chemical reaction with the acid gases. The reaction process is sometimes referred to as “gas sweetening.” As a result of the gas sweetening process, a treated or “sweet” gas stream is created. The sweet gas stream has been substantially depleted of H2S and/or CO2 components. The sweet gas can be further processed for liquids recovery, that is, by condensing out heavier hydrocarbon gases. The extracted CO2 may be sold or otherwise used for enhanced oil recovery operations.
Traditionally, the removal of acid gases using chemical solvents involves counter-currently contacting the natural gas/flue gas stream with the solvent. The raw gas stream is introduced into the bottom section of a contacting tower column absorber, which is also referred to as a contacting tower, a column absorber, or simply a tower. In the subsequent text the term “column absorber” will be used. At the same time, the solvent solution is directed into a top section of the column absorber. The column absorber has trays, packings or other internal components. As the liquid solvent cascades through the column absorber it absorbs the undesirable acid gas components and carries them away through the bottom of the contacting column absorber as part of a “rich” solvent solution. At the same time, gaseous fluid that is largely depleted of H2S and/or CO2 exits at the top of the column absorber.
It is common to use a variety of absorbent liquids to absorb acid gases such as H2S and/or CO2 from gas or hydrocarbon liquid streams. Upon absorption, the absorbent liquid is said to be “rich.” Following absorption, a process of regeneration (also called “desorption”) may be employed to separate acid gases from the active solvent of the absorbent liquid. This produces a “lean” solvent that is then typically recycled for further absorption.
Known counter-current contactor towers used for H2S and CO2 scrubbing tend to be very large and heavy. This creates particular difficulty in offshore oil and gas production applications, where both space and weight is an issue. Similar problems are created in power generation plants requiring removal of CO2 from large quantities of generated flue gas. Accordingly, a need exists for an improved gas processing facility useful for the removal of acid gases from hydrocarbon gas streams in connection with oil and gas recovery that employs primarily smaller contacting devices.
The object of the invention is therefore to provide an improved solution that solves the above problems relating to the separation of acid gases from a gaseous hydrocarbon fluid stream or from a flue gas stream. These objects and others will become apparent from the following description.